Historically, subterranean wells have been drilled by rotating a bit attached to the end of jointed pipe or tubing sections. The jointed pipe string is rotated from the surface, which rotation is transferred to the bit. As the rotating bit drills into the earth, additional sections or joints of pipe must be added to drill deeper. A significant amount of time and energy is consumed in adding and removing new sections of pipe to the drill string.
Coiled tubing, such as described in U.S. Pat. No. 4,863,091, is available in virtually unlimited lengths and has been used for a variety of purposes in the exploration and production of hydrocarbons from subterranean wells. Coiled tubing is widely used in the oil and gas industry for a variety of purposes and applications, including, but not limited to, drilling, completion, and work over operations. For example, coiled tubing may be run into a subterranean well to produce hydrocarbons from the subterranean formation, to fracture or perforate the subterranean formation, to perform well data acquisition, introduce fluids, and to clean out the wellbore.
Coiled tubing is typically supplied to the oilfield on a large spool or reel that contains thousands of feet of continuous, relatively thin-walled tubing that typically has an outside diameter between about 1″ to 4.5″. During use, the tubing is spooled off the reel and onto a device or “gooseneck” that bends and guides the coiled tubing into another device, such as an injector head. The injector head functions to grip the tubing and mechanically force it into, and withdraw it from, the wellbore.
Coiled tubing rigs primarily consist of an injector head for inserting and removing the coiled tubing from the wellhead, a spool reel for storing and transporting the coiled tubing, a power pack to power the injector head, and a control room to operate the machinery.
A typical coiled tubing injector is comprised of two continuous chains, though more than two can be used. The chains are mounted on sprockets to form elongated loops that counter rotate. A drive system applies torque to the sprockets to cause them to rotate, resulting in rotation of the chains. In most injectors, chains are arranged in opposing pairs, with the pipe being held between the chains. Grippers carried by each chain come together on opposite sides of the tubing and are pressed against the tubing. The injector thereby continuously grips a length of the tubing as it is being moved in and out of the well bore. The “grip zone” or “gripping zone” refers to the zone in which grippers come into contact with a length of tubing passing through the injector.
A drive system for a coiled tubing injector includes at least one motor. For larger injectors, intended to carry heavy loads, each chain will typically be driven by a separate motor. The motors are typically hydraulic, but electric motors can also be used. Each motor is coupled either directly to a drive sprocket on which a chain is mounted, or through a transmission to one or more drive sockets. Low speed, high torque motors are often the preferred choice for injectors that will be carrying heavy loads, for example long pipe strings or large diameter pipe. However, high speed, low torque motors coupled to drive sprockets through reduction gearing are also used.
The coiled tubing injector head is conventionally positioned above the wellhead. In work over operations, for example, the injector head may be suspended above the wellbore by a crane or other device. A lubricator may be used to connect the injector head to the wellhead (including, for example, a blowout preventer) at the top of the wellbore to prevent the coiled tubing from buckling or otherwise deforming prior to entering the wellbore.
Typically, coiled tubing operations are performed from a crane where the crane suspends the injector above the wellbore and the injector deploys the coiled tubing downhole. Further, in this configuration, lubricators are positioned between the wellbore and the injector in a substantially vertical manner. In these applications, the lubricators are often load-bearing themselves. Overhead loads can fall and pose a danger to people around the coiled tube injector.
It is therefore advantageous to develop apparatuses and methods of transmitting coiled tubes downhole from a horizontal position. Further, without cranes, the injector is easier to move from wellhead to wellhead. In such applications, it is also advantageous to have a coil tubing lubricator substantially parallel to and near ground level with respect to the tubing for lubricating and assembly of downhole tools.